Well logs are measurements, typically with respect to depth, of selected physical parameters of earth formations penetrated by a wellbore. Well logs are typically recorded by inserting various types of measurement instruments disposed on an integrated measurement platform into a wellbore, moving the instruments along the wellbore, and recording the measurements made by the instruments. One type of well log recording includes lowering the instruments at the end of an armored electrical cable, and recording the measurements made with respect to the length of the cable extended into the wellbore. These are known as “wireline” measurements. Depth within the wellbore is inferred from the extended length of the cable. Recordings made in this way are substantially directly correlated to measurement depth within the wellbore. Other methods for measurement include a “logging while drilling” (LWD) method, a measurement while drilling (MWD), and a memory logging method. The LWD method involves attaching the instruments to the lower portion of a drilling tool assembly used to drill the wellbore. LWD and wireline tools are typically used to measure the same sort of formation parameters, such as density, resistivity, gamma ray, neutron porosity, sigma, ultrasonic measurement, etc. MWD tools are typically used to measure parameters closely associated with drilling, such as well deviation, well azimuth, weight-on-bit, mud flow rate, annular borehole pressure, etc.
The aforementioned well logging tools may be conveyed into and out of a well via wireline cable, drilling pipe, coiled tubing, slickline, etc. Further, LWD and MWD measurement methods allow for measurement in the drill string while the bit is cutting, or measurement while tripping down or up past a section of a borehole that had been drilled at a previous time.
A major distinction between measurements taken using wireline tools and measurements taken using LWD/MWD tools is the ability to get the raw data back to the surface. With a wireline tool, all of the raw data can be sent directly to the surface via the armored cable. However, in the LWD/MWD environment, there is no physical communication medium connecting the tool to the surface. The typical means of communication between the tool and the surface is via mud pulse telemetry, wherein the pressure of the drilling fluid (mud) flowing through the interior of the drilling tool assembly is modulated to convey information. This is an extremely narrow bandwidth communication channel. Accordingly, only small amounts of information can be conveyed to the surface. Larger amounts of data must be stored in the tool for later retrieval at the surface.
FIG. 1 shows a typical manner in which well log data are acquired in the wireline environment. An assembly or “string” of well log instruments (including logging sensors or “sondes” (8, 5, 6 and 3) as will be further explained) is lowered into a wellbore (32) drilled through the earth (36) at one end of an armored electrical cable (33). The cable (33) is extended into and withdrawn from the wellbore (32) by means of a winch (11) or similar conveyance known in the art. The cable (33) transmits electrical power to the instruments (including logging sensors 8, 5, 6, 3) in the string, and communicates signals corresponding to measurements made by the instruments (including logging sensors 8, 5, 6, 3) in the string to a recording unit (7) at the earth's surface. The recording unit (7) includes a device (not shown) to measure the extended length of the cable (33). Depth of the instruments (including logging sensors 8, 5, 6, 3) within the wellbore (32) is inferred from the extended cable length. The recording unit (7) includes equipment (not shown separately) of types well known in the art for making a record with respect to depth of the instruments within the wellbore (32).
The logging sensors (8, 5, 6, and 3) may be of any type known in the art. These include gamma ray sensors, neutron porosity sensors, electromagnetic induction resistivity sensors, nuclear magnetic resonance sensors, and gamma-gamma (bulk) density sensors. Some logging sensors, such as (8, 5, and 6) are contained in a sonde “mandrel” (axially extended cylinder) which may operate effectively near the center of the wellbore (32) or displaced toward the side of the wellbore (32). Others logging sensors, such as a density sensor (3), include a sensor pad (14) disposed to one side of the sensor housing (13) and have one or more detecting devices (17) therein. In some cases, the sensor (3) includes a radiation source (18) to activate the formations proximate the wellbore (32). Such logging sensors are typically responsive to a selected zone (9) to one side of the wellbore (32). The sensor (3) may also include a caliper arm (15), which serves both to displace the sensor (3) laterally to the side of the wellbore (32) and to measure an apparent internal diameter of the wellbore (32).
FIG. 2 shows a typical configuration for acquiring well log data using a logging while drilling (LWD) and measurements while drilling (MWD) system (39). The LWD/MWD system (39) may include one or more collar sections (44, 42, 40, 38) coupled to the lower end of a drill pipe (20). The LWD/MWD system (39) includes a drill bit (45) at the bottom end to drill the wellbore (32) through the earth (36). In this example, drilling is performed by rotating the drill pipe (20) by means of a rotary table (43). However, drilling may also be performed by top drives or coiled tubing drilling or downhole motors or with rotary steerable systems. During rotation, the pipe (20) is suspended by equipment on a drill rig (10) including a swivel (24), which enables the pipe (20) to rotate while maintaining a fluid tight seal between the interior and exterior of the pipe (20). Mud pumps (30) draw drilling fluid (“mud”) (26) from a tank or pit (28) and pump the mud (26) through the interior of the pipe (20), down through the LWD/MWD system (39), as indicated by arrow (41). The mud (26) passes through orifices (not shown) in the bit (45) to lubricate and cool the bit (45), and to lift drill cuttings through an annulus (34) between the pipe (20), LWD/MWD system (39), and the wellbore (32).
The collar sections (44, 42, 40, 38) include logging sensors (not shown) which make measurements of various properties of the earth formations through which the wellbore (32) is drilled. These measurements are typically recorded in a recording device (not shown) disposed in one or more of the collar. LWD systems known in the art typically include one or more logging sensors (not shown) which measure formation parameters, such as density, resistivity, gamma ray, neutron porosity, sigma, etc. as described above, which may be used to determine formation lithology, etc. MWD systems known in the art typically include one or more logging sensors (not shown) which measure selected drilling parameters, such as inclination and azimuthal trajectory of the wellbore (32). MWD systems also provide the telemetry (communication system) for any MWD/LWD tool logging sensors in the drill string.
The LWD/MWD system (39) typically includes a mud pressure modulator (not shown separately) in one of the collar sections (44). The modulator (not shown) applies a telemetry signal to the flow of mud (26) inside the system (39) and pipe (20) where the telemetry signal is detected by a pressure sensor (31) disposed in the mud flow system. The pressure sensor (31) is coupled to detection equipment (not shown) in the surface recording system (7A), which enables recovery and recording of information transmitted in the telemetry scheme sent by the MWD portion of the LWD/MWD system (39). The telemetry scheme includes a subset of measurements made by the various logging sensors (not shown separately) in the LWD/MWD system (39). The majority of the measurements made by the logging sensors in the LWD/MWD system (39) are not retrieved until the system is withdrawn from the wellbore.
One formation parameter that is of particular interest to the drilling operator is formation lithology. “Lithology” refers to the physical character and composition of the rock. Thus, a lithologic log indicates the different rock strata within the formations penetrated by the borehole. Once a hole has been drilled, a lithologic log may be produced by obtaining formation spectroscopy data using a wireline neutron tool, and subsequently processing the data at the surface to provide the desired log. However, this process is of no use while the hole is being drilled. To give the drilling operator a picture of the lithology as the hole is being drilled, it is conventional to examine the drill cuttings brought to the surface by the circulated drilling mud. This process generates what is known as a “mud log”.
An example of a conventional, manually-generated mud log is shown in FIG. 3. In this log, drilling time is recorded in area 51 at 2-foot intervals, and time is recorded in minutes per foot. This information is important as it gives the operator information some basic information about what type of rock is being drilled through (some rocks, e.g., shales, drill “slow”, while others, e.g., limestone, drill “fast”). In the next area (53), titled “litho”, the mud logger uses standard symbols and colors to indicate the type of rock that is being drilled based upon the well cuttings. In the third area (55), the mud logger provides a written description of the samples he or she has examined. The last step is for the mud logger to pick and note formation horizons. On this log, the “L-1”, “L-2”, and “Neva” formations are indicated.
An example of a more modern yet conceptually analogous mud log is shown in FIG. 4. In this log, the drilling time data in area 51 and the pictorial representation of the lithology in area 53 are generated by computer. However, the mud logger still has to manually examine the cuttings to provide the notations in area 55.
Regardless of what type of mud log is used, conventional mud logs have certain limitations. For example, as the depth of the hole increases, the latency of the log, i.e., the time between when the actual cutting occurs and when the corresponding cuttings are circulated to the surface, becomes large. In addition, the cuttings from different depths may become commingled in the mud, giving an inaccurate representation of the formation.
As noted previously, once the hole has been drilled, other types of spectroscopy-derived lithology information may be obtained using a wireline tool. In the conventional wireline-conveyed measurement, the entire measured gamma-ray energy spectrum is transmitted to the surface, where it is processed to derive elemental yields and subsequent lithological indicators. This is possible in the wireline environment because of the transmission bandwidth available through the electrical conductors of the wireline. Information obtained from the mud log typically will be considered together with information obtained using wireline tools to determine whether to complete the hole.
An example of a known surface spectroscopy processing technique is described below. In general, however, it should be understood that spectroscopy processing requires a large amount of raw data; an amount of data that greatly exceeds the transmission bandwidth in a typical LWD/MWD system. In addition, conventional spectroscopy processing requires operator input to guide the processing and ultimately produce a lithology model. For both of these reasons, in the LWD/MWD environment, spectroscopy processing is something that conventionally has only been done at the surface and after the tool has been retrieved from the hole.
FIG. 5 shows a flow diagram of the typical steps involved in surface spectroscopy processing. Initially, the raw spectral data is acquired by a downhole tool (Step 400). The downhole tool may include such tools as a Reservoir Saturation Tool (RST), a Combinable Production Logging Tool (CPLT), etc. (RST and CPLT are marks of Schlumberger). The raw spectral data is then pre-processed (Step 402). Pre-processing includes determining foreground and background spectra as well as accumulation and background subtraction. The result of the pre-processing is a net capture spectrum. The net capture spectrum is subsequently processed using spectral stripping (Step 404). During spectral stripping, the elemental yields, offsets, and gains are calculated using the net capture spectra and the depth information (406).
The results from the spectral processing are then used for borehole logic processing (Step 408). During the borehole logic processing, depth information (406) and data from other well logging tools (410) may be used in conjunction with the spectroscopy information to identify the composition of the drilling mud system, and allow for corrections to be made as necessary. In some cases user intervention (412) may be required to facilitate the borehole logic processing. The elemental yields calculated during spectral stripping (Step 404) are re-distributed, as required, based on the results of the borehole logic processing (Step 414). The re-distributed yields are then used in pre-spectroscopy to lithology processing to correct the calculated sulfur and iron yields, filter the elemental yields, compute the apparent salinity, and baseline certain yields in preparation for further processing (416). Oxides closure processing is subsequently performed to determine the dry weight elemental concentrations of particular elements, such as silicon, calcium, sulfur, iron, titanium, etc. (Step 418). The dry weight elemental concentrations are then used in spectroscopy-to-lithology processing to determine the dry weights of clay, carbonate, quartz-feldspar-mica (QFM), pyrite, anhydride, siderite, salt and coal (Step 420). The dry weight elemental concentrations and calculated lithology fractions are also used in formation logic processing to determine the the appropriate clay model (e.g., arenite, sub-arkose, arkose, etc.), sulfur mineral model, and presence of siderite, coal and salt (Step 422).
The results from the spectroscopy-to-lithology processing (Step 420) and the formation logic processing (Step 422) are used to compute matrix properties (Step 424), such as matrix density, matrix neutron, matrix sigma, matrix photoelectric factor, etc. The uncertainties for the dry weight of the elements are subsequently calculated to ensure the robustness of the above calculations (Step 426).